Configurations and methods for ngl recovery for high nitrogen content feed gases

ABSTRACT

A low cost and efficient design is used to convert a propane recovery process based on low nitrogen content feed gas to an ethane recovery process based on a high nitrogen feed gas while achieving over 95 mole % ethane recovery while maintaining a 99% propane recovery, and achieved without additional equipment.

This application claims priority to U.S. Provisional Application Ser. No. 61/703,654 filed on Sep. 20, 2012. This and all other referenced extrinsic materials are incorporated herein by reference in their entirety. Where a definition or use of a term in a reference that is incorporated by reference is inconsistent or contrary to the definition of that term provided herein, the definition of that term provided herein is deemed to be controlling.

FIELD OF THE INVENTION

The field of the invention is natural gas processing, more specifically, conversion of a low nitrogen feed gas plant operating on C₃ recovery to a high nitrogen feed gas plant operating on C₂ recovery.

BACKGROUND OF THE INVENTION

The following description includes information that may be useful in understanding the present invention. It is not an admission that any of the information provided herein is prior art or relevant to the presently claimed invention, or that any publication specifically or implicitly referenced is prior art.

Natural gas is a hydrocarbon gas mixture that occurs in nature and can be found under deep underground rock formations. The exact composition of natural gas varies from source to source and can comprise different percentages of hydrocarbons (e.g., methane, ethane, propane, and butane), as well as other constituents (e.g., carbon dioxide, oxygen, nitrogen, and hydrogen sulphide).

Before natural gas can be used as an energy source, it must be processed to remove impurities and to “recover” the desired hydrocarbons, meaning that the desired hydrocarbons are separated by kind and converted into separate streams of liquid natural gas (LNG). Numerous natural gas separation processes and systems, referred to herein as “NGL plants,” are known. In a typical NGL plant, a pressurized feed gas stream originating from a natural gas source is cooled by a heat exchanger, typically using propane refrigeration when the feed gas is rich. As the feed gas stream is cooled, the heavier hydrocarbons (e.g., ethane, propane, butane) condense from the cooled gas and form a liquid stream. The liquid stream is then separated from the gas stream and expanded with a turbo expander and fractionated in distillation columns (e.g., de-deethanizer or demethanizer) to further separate lighter components (e.g., methane, nitrogen, volatile gases) as overhead vapor from the heavier components. The system parameters for a NGL plant (e.g., volumetric flow rates, temperatures, pressures) will vary depending on the particular composition and condition (e.g., pressure, temperature) of the natural gas being processed. System parameters will also vary depending on the desired hydrocarbons that need to be recovered (e.g., methane, ethane, propane, etc.). As long as the feed gas composition does not deviate significantly from the system parameters, known separation processes can achieve high recovery levels.

Crude oil and natural gas are often found together in the same reservoir, such as a crude oil well. In such cases, the crude oil extraction process can be enhanced by injecting nitrogen into the reservoir. Consequently, the nitrogen content in the natural gas increases over time. This increase in nitrogen can reduce the operational efficiency and recovery levels of the NGL plant over time. For example, NGL plants are typically designed to process feed gas with a nitrogen content of 1 to 2 mole % or lower. As the enhanced crude oil recovery process continues, the nitrogen content can be increased to 17 to 20 mole % and higher. The high nitrogen content dilutes the feed gas and changes the temperature profile of the NGL plant, which reduces NGL recovery levels and plant processing capacity. Thus, there is a need for new NGL plant designs that provide high LNG recovery levels even as nitrogen content of the natural gas increases over time.

The challenge of processing natural gas as nitrogen content increases is further exuberated by the fact that, in some cases, NGL plants are required to recover both ethane (C₂) and propane (C₃). Typically, C₂ recovery processes employ a single distillation column, which usually has a reflux to increase C₂ recovery, such as illustrated in: U.S. Pat. No. 4,519,824 issued to Huebel; U.S. Pat. No. 4,278,457 issued to Campbell et al.; and U.S. Pat. No. 4,157,904 issued to Campbell et al. However, when C₃ is desired, the recovery processes consist of two columns: one column operating as an absorber and the other column operating as a deethanizer column. The design configuration and system parameters for NGL plants can differ significantly, depending on C₃ recovery or C₂ recovery is desired.

Some NGL plants are designed to switch between a C₂ recovery mode and C₂ rejection mode (e.g., C₃ recovery mode). For example, U.S. Pat. No. 7,051,553 to Mak et al, describes a twin reflux NGL plant/process that can switch between a C2 recovery mode and C3 recovery mode. In particular the NGL plant has a first column that receives two reflux streams: one reflux stream comprises a vapor portion of the NGL and the other reflux stream comprises a lean reflux provided by the overhead of a second column. While such a process can accommodate variations in ethane recovery levels (e.g., by switching from C₃ recovery mode to C₂ recovery mode), it nevertheless is limited to the feed gas composition and would require significant process modifications if the nitrogen content in the feed gas is increased to over 20%.

Thus, although various configurations and methods for NGL plants are known, such configurations are not well suited to handle the increase in nitrogen content that occurs during enhanced oil recovery in crude oil wells, especially the NGL plant is required to switch from a C₃ recovery mode to a C₂ recovery mode.

Therefore, there is still a need to provide methods and configurations for improved LNG recovery, especially for crude oil reservoirs that contain both oil and natural gas.

SUMMARY OF THE INVENTION

The inventor has discovered that a high C₃ recovery process designed for a low nitrogen content feed gas, typically 1 to 2 mole %, can be converted to a high C₂ recovery process for a high nitrogen content feed gas, typically 17 to 20 mole % or higher to achieve over 95% ethane recovery while maintaining over 99% propane recovery, in which C₃ refrigeration is used to provide reflux to the deethanizer during C₃ recovery and is converted to provide feed gas chilling during C₂ recovery.

In one aspect of some embodiments, NGL plants and methods employ a two-column NGL recovery configuration having an absorber and a fractionation column that are used for both C₂ recovery and C₃ recovery. The absorber is configured to receive at least two alternate reflux streams, wherein one reflux stream is drawn from an overhead vapor and/or liquid from the distillation column during C₃ recovery and wherein the other reflux streams are drawn from the chilled residue gas and the chilled feed gas during C₂ recovery. Such contemplated methods allow conversion of a C₃ recovery plant to a C₂ recovery plant when the feed gas nitrogen content increases from 1 mole % to over 20 mole %.

Viewed from a different perspective, it should be recognized that contemplated methods and configurations effectively utilize propane refrigeration to provide refluxes to the absorber and fractionation column during C₃ recovery and can be converted to provide refluxes with chilled feed gas and residue gas during C₂ recovery, wherein the overhead vapor from the fractionation column is re-routed to the absorber bottom.

Contemplated methods advantageously recover the refrigerant content of the liquids from the expander suction separator and the absorber bottom by chilling the feed gas during propane recovery, wherein these liquids are directly returned to the columns during ethane recovery.

In some configurations, during ethane recovery about 20% to 30% of the feed gas is chilled, bypassing the expander, and is provided as reflux to the absorber. In addition, about 10% to 50% of the total residue gas is chilled, providing a second reflux to the absorber, whereby, about 95% C₂ is recovered while maintaining over 99% C₃ recovery.

Contemplated configurations are especially advantageous in application to NGL recovery plants that require C₃ recovery in the initial operation with a low nitrogen content gas and are then converted to recover C₂ with a high nitrogen feed gas in the later phase.

Various objects, features, aspects and advantages of the inventive subject matter will become more apparent from the following detailed description of preferred embodiments, along with the accompanying drawing figures in which like numerals represent like components.

BRIEF DESCRIPTION OF THE DRAWING

FIG. 1 is a schematic of one exemplary process and configuration for C₃ recovery with a low nitrogen content feed gas according to the inventive subject matter. The solid lines pertain to the C₃ recovery operation while the fathom lines pertain to the C₂ recovery operation.

FIG. 2 is a heat and mass table for the process shown in FIG. 1.

FIG. 3 is a schematic of one exemplary process and configuration for C₂ recovery with a high nitrogen content feed gas according to the inventive subject matter. The solid lines pertain to the C₂ recovery operation while the fathom lines pertain to the C₃ recovery operation.

FIG. 4 is a heat and mass table for the process shown in FIG. 3.

FIG. 5 is heat composite curve for core exchanger 51 operating in the C₃ recovery mode with a low nitrogen content feed gas according to the inventive subject matter.

FIG. 6 is heat composite curve for core exchanger 51 operating in the C₂ recovery mode with a high nitrogen content feed gas according to the inventive subject matter.

DETAILED DESCRIPTION

The following discussion provides many example embodiments of the inventive subject matter. Although each embodiment represents a single combination of inventive elements, the inventive subject matter is considered to include all possible combinations of the disclosed elements. Thus if one embodiment comprises elements A, B, and C, and a second embodiment comprises elements B and D, then the inventive subject matter is also considered to include other remaining combinations of A, B, C, or D, even if not explicitly disclosed.

FIG. 1 shows an exemplary C₃ recovery process, in which feed gas 1 enters an NGL plant at 100° F. and about 900 psig, with a feed gas composition as shown in the overall heat and mass table of FIG. 2. Feed gas stream 2 is cooled to about −40° F. by heat exchange with residual gas stream 12 from the absorber, forming stream 4 which is separated in separator 52, producing liquid stream 70, and vapor stream 8. Vapor stream 8 is expanded in expander 53 to about 430 psig, forming stream 11 at about −95° F., which is fed to the lower section of absorber 54. The power produced from expander 53 is used to drive re-compressor 65. Liquid stream 70 is let down in pressure in JT valve 71 to about 430 psig, forming stream 10 at about −75° F., and is then heated to −20° F. by the feed gas in exchanger 51, forming stream 32, prior to feeding to the bottom of absorber 54.

Absorber 54 is refluxed with two streams; liquid stream 74 and the vapor stream 80, producing an ethane depleted overhead stream 12 at −60° F., and an ethane rich bottom stream 13 at 25° F. The refrigerant content in the overhead stream 12 is recovered by chilling the feed gas 1, and the bottom stream 13 is pumped by pump 55 and heated by feed gas 1 to about 90° F., forming stream 7, prior to entering the mid-section of fractionator 58. The fractionator produces an ethane rich overhead stream 15 at 16° F., and a propane rich bottom stream 16 at 210° F. Side reboilers 59 and 60 are used to reduce the reboiler duty for energy conservation while the fractionator 58 bottom temperature is controlled by reboiler 61, maintaining the ethane content in stream 16 (NGL) to below 0.01 mole %.

The fractionator overhead stream 15 is cooled by propane refrigeration in chiller 62 to about −20° F., forming stream 30, which is separated in separator 63 into vapor stream 14 and liquid stream 31, supplying refluxes for absorber 54 and fractionator 58.

Overall heat and material balance for the C₃ recovery process is shown in the table of FIG. 2.

FIG. 3 shows an exemplary C₂ recovery process, in which feed gas 1 enters a NGL plant at 100° F. and about 900 psig, with a feed gas composition as shown in the overall heat and mass table of FIG. 4. Feed gas stream 1 is split into two portions, stream 2 and stream 3, where stream 2 constitutes about 20% to 30% of the total feed gas rate, and is cooled by the residue gas in exchanger 51.

The other portion, stream 3, is cooled by propane chiller 62 to about −22° F., forming stream 30, which is further cooled in exchanger 51 to about −40° F., forming stream 80, which is separated in separator 52, producing liquid stream 70 and vapor stream 8. Vapor stream 8 is expanded in expander 53 to about 430 psig, forming stream 11 at about −105° F., which is fed to the lower section of absorber 54.

The power produced from expander 53 is used to drive re-compressor 65. Liquid stream 70 is let down in pressure to about 450 psig in JT valve 71 and combined with the fractionator overhead vapor stream 15 and fed to the bottom section of absorber 54.

Absorber 54 is refluxed with two reflux streams, feed gas stream 5 and the residue gas recycle stream 27, producing an ethane depleted overhead stream 12 at −150° F., and an ethane rich bottom stream 13 at −66° F. The absorber overhead stream 12 is used in chilling the feed gas stream 2 and residue gas recycle stream 25 in exchanger 51, and the absorber bottom stream 13 is pumped by pump 55 and is sent to fractionator 58 as reflux stream 77. Fractionator 58 produces an ethane depleted overhead stream 15 and ethane rich bottom stream 16. Side reboilers 59 and 60 are used to reduce reboiler duty for energy conservation, and the temperature of the bottom liquid in fractionator 58 is maintained at 82° F. by reboiler 61, maintaining the methane content in stream 16 (NGL) to below 0.01 mole %.

Overall heat and material balance for the high nitrogen feed gas operation on C₂ recovery is shown in the table of FIG. 4.

It should be particularly appreciated that the contemplated configurations shown in FIGS. 1 and 3 may be used for high nitrogen feed gases for either ethane or propane recovery by repositioning valves and piping. Alternatively, a NGL plant can be designed so that it is transitionable between a C₂ recovery mode and C₃ recovery mode with minimum impact on the process. For example, an NGL plant can be configured with piping and components represented by both the solid lines and the dotted lines in FIGS. 1 and 3, with valves at the intersections of solid and fathom lines. The valves can be operated manually or automatically to transition between recovery modes. In this manner, NGL plants can process a feed gas that has an increase in nitrogen content over time, such as the feed gas from a crude oil reservoirs that is processed using nitrogen-enhanced methods.

With the contemplated plant designs, C₃ recovery can be maintained at over 99% during the C₃ recovery mode, while C₂ recovery can be maintained at 95% while maintaining a 99% C₃ recovery. When C₃ recovery is required, the propane chiller is used for cooling a portion of the feed gas, and when C₃ recovery is desirable, the propane chiller is used as a reflux condenser for the absorber and fractionator.

When operating on C₂ recovery mode, the absorber bottom liquid stream is fed directly to the top tray of the fractionator column by valve switching, and when C₃ recovery is required, the absorber bottom stream is heated and routed to the mid-section of the fractionator. Thus, it should be noted that during C₃ recovery, the fractionator overhead vapor is chilled and partially condensed with propane refrigeration and the absorber bottoms, producing a vapor and liquid stream. The ethane rich vapor stream is further chilled by the absorber column overhead forming a reflux stream. During C₂ recovery, the fractionator overhead is routed to the bottom of the absorber for rectification and recovery of the ethane and heavier components.

With respect to suitable feed gas streams, it is contemplated that various feed gas streams are appropriate, and especially suitable fed gas streams may include various hydrocarbons of different molecular weight. With respect to the molecular weight of contemplated hydrocarbons, it is generally preferred that the feed gas stream predominantly includes C₁-C₆ hydrocarbons. However, suitable feed gas streams may additionally comprise acid gases (e.g., carbon dioxide, hydrogen sulfide) and other gaseous components (e.g., hydrogen). Consequently, particularly preferred feed gas streams are natural gas and natural gas liquids.

Thus, it should be especially recognized that in contemplated configurations, the cooling requirements for the first column are at least partially provided by product streams and recycle gas, and that the C₂/C₃ recovery can be varied by employing a different reflux stream. With respect to the C₂ recovery, it is contemplated that such configurations provide at least 85%, more preferably at least 90%, and most preferably at least 95% recovery, while it is contemplated that C₃ recovery will be at least 98%, more preferably at least 98%, and most preferably at least 99%. Further related configurations, contemplations, and methods are described in co-owned International Patent Applications with the publication numbers WO 2005/045338 and WO 2007/014069, both of which are incorporated by reference herein.

Thus, specific embodiments and applications of C₂ recovery and C₂ rejection configurations and methods therefore have been disclosed. It should be apparent, however, to those skilled in the art that many more modifications besides those already described are possible without departing from the inventive concepts herein. The inventive subject matter, therefore, is not to be restricted except in the spirit of the present disclosure. Moreover, in interpreting the specification and contemplated claims, all terms should be interpreted in the broadest possible manner consistent with the context. In particular, the terms “comprises” and “comprising” should be interpreted as referring to elements, components, or steps in a non-exclusive manner, indicating that the referenced elements, components, or steps may be present, or utilized, or combined with other elements, components, or steps that are not expressly referenced.

As used herein, and unless the context dictates otherwise, the term “coupled to” is intended to include both direct coupling (in which two elements that are coupled to each other contact each other) and indirect coupling (in which at least one additional element is located between the two elements). Therefore, the terms “coupled to” and “coupled with” are used synonymously.

Groupings of alternative elements or embodiments of the invention disclosed herein are not to be construed as limitations. Each group member can be referred to and claimed individually or in any combination with other members of the group or other elements found herein. One or more members of a group can be included in, or deleted from, a group for reasons of convenience and/or patentability. When any such inclusion or deletion occurs, the specification is herein deemed to contain the group as modified thus fulfilling the written description of all Markush groups used in the appended claims.

The recitation of ranges of values herein is merely intended to serve as a shorthand method of referring individually to each separate value falling within the range. Unless otherwise indicated herein, each individual value with a range is incorporated into the specification as if it were individually recited herein. Unless the context dictates the contrary, all ranges set forth herein should be interpreted as being inclusive of their endpoints and open-ended ranges should be interpreted to include only commercially practical values. Similarly, all lists of values should be considered as inclusive of intermediate values unless the context indicates the contrary. All methods described herein can be performed in any suitable order unless otherwise indicated herein or otherwise clearly contradicted by context. The use of any and all examples, or exemplary language (e.g. “such as”) provided with respect to certain embodiments herein is intended merely to better illuminate the invention and does not pose a limitation on the scope of the invention otherwise claimed. No language in the specification should be construed as indicating any non-claimed element essential to the practice of the invention.

As used in the description herein and throughout the claims that follow, the meaning of “a,” “an,” and “the” includes plural reference unless the context clearly dictates otherwise. Also, as used in the description herein, the meaning of “in” includes “in” and “on” unless the context clearly dictates otherwise. 

What is claimed is:
 1. A method of flexibly recovering ethane from a feed gas, comprising: feeding into a demethanizer a top reflux and a second reflux below the top reflux, wherein the demethanizer produces a demethanizer bottom product and a demethanizer overhead product; feeding at least part of the demethanizer bottom product to a deethanizer to produce a deethanizer bottom product and a deethanizer overhead product; feeding a portion of the demethanizer overhead product back to the demethanizer as the top reflux during ethane recovery, and feeding a portion of the deethanizer overhead product back to the demethanizer as the top reflux during ethane rejection; and wherein the demethanizer is operated at a higher pressure than the deethanizer during ethane recovery, and wherein the demethanizer is operated at a lower pressure than the deethanizer during ethane rejection.
 2. The method of claim 1 further comprising a step of expanding the feed gas in a turbo expander to produce a partially expanded feed gas and a further step of cooling and additionally expanding a first portion of the partially expanded feed gas to produce the second reflux.
 3. The method of claim 2 further comprising a step of cooling a second portion of the partially expanded feed gas to produce a partially condensed feed stream, separating the partially condensed feed stream into a vapor stream and a liquid stream, and expanding the vapor and liquid stream prior to feeding into a demethanizer.
 4. The method of claim 3 further comprising a step of using a demethanizer side reboiler in cooling a third portion of the partially expanded feed gas to produce a cooled feed stream, and combining the cooled feed stream with the chilled or partially condensed feed stream.
 5. The method of claim 3 wherein flow of the third portion of the partially expanded feed gas to the demethanizer side reboiler is decreased relative to flow of the first and second portions of the partially expanded feed gas during ethane rejection.
 6. The method of claim 1 wherein a propane recovery of at least 99% is achieved during ethane recovery and during ethane rejection.
 7. The method of claim 1 wherein an ethane recovery of at least 95% is achieved during ethane recovery.
 8. A method of changing ethane recovery to ethane rejection operation in a NGL plant, comprising: changing a top reflux of a demethanizer from a demethanizer overhead product to a deethanizer overhead product for ethane rejection; reducing demethanizer pressure to a pressure that is lower than a deethanizer pressure for ethane rejection; and wherein the demethanizer receives a second reflux below the top reflux, and wherein the second reflux is a portion of a feed gas, and wherein the portion of the feed gas is subcooled by the demethanizer overhead product.
 9. The method of claim 8 wherein the demethanizer produces a bottom product that is fed to a deethanizer that produces the deethanizer overhead product.
 10. The method of claim 8 wherein the feed gas is cooled before the step of sub-cooling by expanding the feed gas in a turbo expander.
 11. The method of claim 8 wherein the demethanizer is reboiled using heat from the feed gas.
 12. The method of claim 8 wherein one portion of the feed gas is cooled in a feed gas heat exchanger, wherein another portion of the feed gas is cooled in a demethanizer reboiler heat exchanger.
 13. The method of claim 12 wherein during ethane rejection flow of the one portion of the feed gas is increased relative to flow of the another portion of the feed gas.
 14. The method of claim 8 wherein the demethanizer pressure is between 445 psig and 475 psig or at least 475 psig, and wherein the deethanizer pressure is between 319 psig and 450 psig.
 15. A method of changing ethane recovery to ethane rejection operation in an NGL plant, comprising: providing a demethanizer that receives a top reflux and a second reflux below the top reflux, wherein the demethanizer is fluidly coupled to a deethanizer; cooling one portion of a feed gas in a feed gas heat exchanger using a demethanizer overhead product to so produce the second reflux, cooling another portion of the feed gas in a demethanizer side reboiler heat exchanger to so produce a demethanizer feed stream; changing the top reflux of the demethanizer from the demethanizer overhead product to a deethanizer overhead product for ethane rejection; and increasing flow of the one portion relative to flow of the another portion for ethane rejection.
 16. The method of claim 15 further comprising a step of reducing an operating pressure in the demethanizer to a pressure that is lower than an operating pressure in the deethanizer pressure for ethane rejection
 17. The method of claim 15 wherein the demethanizer produces a bottom product that is fed to the deethanizer.
 18. The method of claim 15 wherein an operating pressure in the demethanizer is between 445 psig and 475 psig or at least 475 psig, and wherein an operating pressure in the deethanizer is between 319 psig and 450 psig.
 19. The method of claim 15 wherein the deethanizer produces a deethanizer bottom product, and further comprising a step of feeding the deethanizer bottom product into a depropanizer.
 20. The method of claim 15 wherein the feed gas has a pressure of at least 1000 psig, and further comprising a step of expanding the feed gas in a turbo expander prior to the step of cooling the one and the another portion. 